The present invention provides improvements in the production of hydrocarbons from subterranean formations. More particularly, the present invention provides improved solutions and methods for fracture stimulation in a subterranean formation while using a relative permeability modifier to reduce fluid leak off therefrom.
One method typically used to increase the effective drainage area of well bores penetrating subterranean formations is fracture stimulation. Fracture stimulation, or “fracturing,” comprises pumping a fracturing fluid into a well bore at a certain pressure and against a selected surface of a subterranean formation intersected by the well bore to create or enhance a fracture therein.
Fracture stimulation may be used in both vertical and horizontal wells. Fracturing horizontal wells may be undertaken in several situations, including situations where the formation has: (1) restricted flow caused by low vertical permeability, the presence of shale streaks or formation damage; (2) low productivity due to low formation permeability; (3) natural fractures in a direction different from that of induced fractures, thus induced fractures have a high chance of intercepting the natural fractures; or (4) low stress contrast between the pay zone and the surrounding layers. In the fourth case, a large fracturing treatment of a vertical well likely would not be an acceptable option since the fracture would grow in height as well as length. Drilling a horizontal well and creating either several transverse or longitudinal fractures may be preferable as they may allow rapid depletion of the reservoir through one or more fractures. “Zone” as used herein simply refers to a portion of the formation and does not imply a particular geological strata or composition.
Selective or pinpoint fracture stimulation of horizontal open hole wells may be performed if desired using coiled tubing or normal tubing and a specialized fracture-jetting tool located at the end. The normal selective or pinpoint fracture stimulation involves pumping stimulation fluids through the tubing and the annular space, both at rates and pressures sufficient to create or enhance a fracture in the formation. For example, for carbonate formations, a “reactive” fluid (as judged by the composition of the formation) such as acid is pumped through the tubing side and at the same time a “nonreactive” fluid (as judged by the composition of the formation) is pumped through the annular space. In the case of a carbonate formation, a water-based fluid may be the nonreactive fluid. Both fluids are mixed downhole and are responsible for the fracture creation or enhancement.
In some circumstances, however, the fracturing process may terminate prematurely, for a variety of reasons. For example, the “nonreactive” portion of the stimulation fluid, which usually is intended to advance as the fracture progresses, may undesirably completely leak off into the formation and result in an inefficient fracture stimulation of the well. This undesired loss or leak off is commonly referred to as “fluid loss.” In fracturing treatments, fluid loss into the formation may result in a reduction in fluid efficiency, such that the fracturing fluid cannot propagate the fracture(s) as desired. As used herein, the term “treatment,” or “treating,” refers to any subterranean treatment that uses a fluid in conjunction with a desired function and/or for a desired purpose. The term “treatment,” or “treating,” does not imply any particular action by the fluid or any particular component thereof.
To overcome the problem of such fluid loss into the formation, viscosified or crosslinked fluids may be used. Additional fluid loss control may be provided by crosslinking the gelling agent or by including fluid loss control materials, such as sized solids (e.g., calcium carbonate), silica particles, oil-soluble resins, and degradable particles, in the treatment fluids. However, there are a number of limitations associated with the use of these viscous fluids. For example, their high viscosity may result in higher friction pressures at high rates, which in turn may result in high annular treatment pressures. Well completions dictate the required treatment pressures and rates for the annular space. In most of the cases, to satisfy the completion limitations of the annular space, it is not possible to pump the fluids at high rates to minimize fluid leak off.
In some instances, to prevent fluid loss from occurring, fluid loss control additives may be included in the treatment fluids. Examples of commonly used fluid loss control additives include, but are not limited to, gelling agents, such as hydroxyethylcellulose and xanthan. The fluid loss control materials may be used in combination with or separately from the conventional fluid loss control additives.
Chemical fluid loss control pills also may be used to combat fluid loss. Conventional chemical fluid loss control pills may be characterized as either solids-containing pills or solids-free pills. Examples of solids-containing pills include sized-salt pills and sized-carbonate pills. These solids-containing pills often are not optimized for the particular downhole hardware and conditions that may be encountered. For instance, the particle sizes of the solids may not be optimized for a particular application and, as a result, may increase the risk of invasion into the interior of the formation matrix, which may greatly increase the difficulty of removal by subsequent remedial treatments. Additionally, high-solids loading in the pills, in conjunction with the large volumes of these pills needed to control fluid losses, may greatly increase the complexity of subsequent cleanup. Furthermore, high loading of starches and biopolymers in the sized salt pills may add to the difficulty of cleanup either by flow back or remedial treatments. Solids-free fluid loss control pills commonly comprise hydrated polymer gels that may not be effective without some invasion into the formation matrix. These pills typically require large volumes to control fluid loss and remedial treatments to remove.
Once fluid loss control is no longer required, for example, after completing a fracturing treatment, remedial treatments may be required to remove the previously placed pills, for example, so that the wells may be placed into production. For example, a chemical breaker, such as an acid, oxidizer, or enzyme may be used to either dissolve the solids or reduce the viscosity of the pill. In many instances, however, use of a chemical breaker to remove the pill from inside the well bore and/or the formation matrix may be either ineffective or not a viable economic option. For example, due to production equipment in the well bore, uniform placement of the breaker into the portion of the formation treated with the pill may not be possible. Furthermore, the chemical breakers may be corrosive to downhole tools. Additionally, as the chemical breakers leak off into the formation, they may carry undissolved fines that may plug and/or damage the formation or may produce undesirable reactions with the formation.